7 replies to this topic

[pmunishankar]

Dear All,

 

We have a natural gas distribution network that supplies natural gas to industrial customers. The supplied gas is dehydrated but not sweetened. It contains H2S of 1000 ppm. We (distribution company) receive gas from upstream company. Upstream company doesnt have any contractual obligation to supply sweet gas to us. Our management has decided to supply sweetened gas (4 ppmv H2S) customers.

 

The challenge in this is which process to select. About 95% of the plants in the world are Amine Process. If we use this process, we may have to put another dehydration unit as Amine Plant outlet gas is saturated with water. We are exploring other processes like Physical Solvent / Molecular Sieves / Adsorption Processes etc.

 

If any one has ever came across similar situation, please do share with me.

 

Gas Capacity: 1500 MMSCFD, Pressure: 900 psig, H2S Content: 1000 ppmv, Dry Gas; 5 lb H2O/MMSCF

Outlet Concentration Desired: 4 ppmv (H2S)

 

Thanks and Regards,

Muni Shankar

[Art Montemayor]

 

Muni Shankar:

 

Are you really treating 1,500 MM Scfd (one thousand five hundred million standard cubic feet per day)?  Could this be in error?

 

All TEG dehydrating units are designed for dealing with natural gas saturated with water vapor at the inlet conditions.  I suspect your unit is also.

 

All acid gas units treating natural gas are located PRIOR to subjecting the natural gas to TEG dehydration.  Normal process design is done this way because the TEG unit continues to process water-saturated natural gas (since the natural gas exiting an amine system that uses a water solution of amine would be water-saturated).  Therefore, what is your problem?

 

Contrary to what you claim, your existing TEG unit would not have to remove any more water vapor from the natural gas if the same gas was coming from an amine acid gas removal system – the gas would be saturated with water vapor just as it is at present.

 

I certainly would not waste time on studying an adsorption unit for removing H₂S from 1,500 million Scfd.  The system would be extremely huge in size and possibly impractical.  An MDEA amine system in front of the existing TEG unit should work just fine.

 

[pmunishankar]

Dear Art Montemayor,

 

Thanks for your reply.

 

I will explain my problem in detail that will clear points raised by you.

 

Upstream company operates gas wells (40+ wells) and dehydrating TEG units (40+ units) located close to each well. There are no desulfurizing units. The gas from TEG units is routed to transmission headers that supply dehydrated gas to Distributing company. Upstream company owns the assets upto distribution point.

 

Distribution Company receives gas at three distribution points and from there it supplies gas to industrial customers by distribution network. Distribution company owns the distribution points and distribution network.

 

Distribution company wants to desulfurize this dehydrated gas from 1000 ppmv to 4 ppmv, total amount of gas to be treated is 1500 MMSCFD (1500 Million Standard Cubic Feet !!!) at a pressure of 900 psig. Since the received gas is clean and dehydrated, we dont want to go for Amine based desulfurizing units as product gas from those units is saturated with water and we should install TEG units to dehydrate the gas from Amine Units. That is the reason I am looking for any other processes which can desulfurize the gas without saturating it with water. I went through GPSA handbook and serached in internet. All I find is that they are some processes like Adsorption (Molecular Sieves) / Physical Solvent (Selexol / Rectisol etc). But I dont have any idea of their practical implementation any where in the world that would treat such high quantity of gas as ours.

 

If the process warrants to desulfurize in 3 trains such as 3 X 500 MMSCFD, we may want to study that option too.

 

All we want is to avoid dehydration unit post desulfurization as desulfurization unit inlet is already a dehydrated gas.

 

Finally, decision would be taken based on economics. The one which has low capex + opex would be given a green signal. If Amine process including dehydration unit (TEG) post desulfurization unit is cheaper than other processes, we definetely go for Amine Process based units.

 

As I have less knowledge in this field, I am seeking your expert advise to just get started.

 

Thanks again Art Montemayor,

 

Regards,

Muni Shankar

[ankur2061]

Muni Shankar,

 

Treating 1500 MMSCFD sour NG even considering three units of 500 MMSCFD with technology other than amine seems to be a difficult task. However, to get some perspective on other technologies and their scale of economies which treat acid gas refer the attached documents. 

 

Regards,

Ankur.

Attached Files

•  acidgas.pdf   382.34KB   179 downloads
•  gast0203p.pdf   205.91KB   162 downloads
•  890623-2.pdf   399.36KB   155 downloads

[Art Montemayor]

 

Muni Shankar

 

Thank you for your positive response and explanation.  If the gas source is located in the Persian Gulf area, then the gas capacity is probably correct.  What I needed to establish is the capacity – because of its size, the capital investment will also be very large and complex.  The process isn’t complex; but the size of the capacity and its importance as an infrastructure utility requires strategic planning and organization in defining how it would be designed.  I would certainly never “put all my eggs into one basket” (design one, integrated acid gas removal unit to handle all the capacity).  I would divide the acid gas removal capacity into 3 or 4 units (3x 500 MMScfd or 4x 400 MMScfd).  The need for this design is obvious and it raises the amount of capital required because you lose the effect of economy of scale.

 

What you describe is a business tragedy fomented by a lack of local natural gas distribution regulations.  Distributing natural gas that has an H₂S content of 1,000 ppmv is what I would call a bad business decision.  I am not putting the finger of blame on anyone here, but the truth is that that a past decision now impacts on what you have before you: the gas producer is producing not “clean” natural gas but dry natural gas (with less than 7 lb H₂O/MMScf I hope) and excessive H₂S content. 

 

In the USA, sales gas is required to be sweetened to contain no more than a quarter grain H₂S per 100 standard cubic feet (4 parts per million).  Additionally, it is mandatory for distributing gas companies to inject detection mercaptans into the sales gas in order to protect the consuming public.  This is obligatory since pure natural gas has no detectable odor and consequently is a potential danger anywhere a leak can develop or a block valve or cooking range can be left open to flow.

 

Additionally, the removal of any H₂S from a natural gas stream is only 50% of the problem.  The other half of the problem is getting rid of the noxious and toxic H₂S.  This unfortunately, in almost all cases today, requires additional investment in Claus Process plants and elemental sulfur disposal.

 

Normally, all of the above problems and investments are the producing companies’ responsibility – except for the mercaptans addition.  Therefore, it is a simple matter (process-wise) to place the TEG dehydration unit downstream of any acid gas removal process employed by the producer.  In your case, your distribution company seems to have been sold, what I would call, some bad gas.  Normally, if faced with this kind of situation, I would re-negotiate the gas sales contract with the producer.  If that doesn’t work, then I would negotiate for sharing in the installation of the acid gas removal + Claus Unit + Sulfur disposal facilities prior to the existing TEG unit(s).  This is a very large undertaking and would probably involve some world-scale contractors in the planning, design, and execution.  It certainly isn’t something we can resolve in this Forum.

 

[pmunishankar]

Thanks a lot Ankur and Art Montemayor for your replies...

 

The preliminary estimates suggest that treating by Amine Process followed by Clauss Unit would cost about $ 1 billion (+/- 50%)!!!!!

for treating 1500 MMSCFD. We dont know whether it is financially viable or not ...

 

Thanks and Regards,

Muni Shankar

[ashetty]

Who would sign a gas contract without any limit on the H2S content of the gas? What i know is that someone has to treat the gas...either you or the upstream operator. Your development plan OBVIOUSLY would have taken into account the addition cost required for sweetening the gas. 1500 MMscfd is a lot of gas..lots of money would be involved. I`m guessing your commercial chaps would have done their economics before signing the contract.

[jojeecares]

Dear Muni,

 

Familiar with you problem. Personally have conducted a similar case study based on process selection for H2S treatment/removal and outcome of the study was the selection of Amine Process followed by TEG Dehydration. Selection was based on CAPEX+OPEX analysis, NPV Analysis and Overall Profitability in Terms of Gas Sales. Although the case study i conducted was for a much smaller unit i.e. 20 MMSCFD but i believe the assumptions would be quite much similar. An adsorption process based on membrane is advantageous in terms of CAPEX+OPEX but demerits include loss of valuable gas in permeate during removal yielding much less sales gas volume. Further demerits include the operating pressure range. Similarly Physical Solvents to have their demerits regarding availability, licensing and operations requiring specifically trained personnel not easily available. At the end, conventional Amine and TEG based units merit the use of conventional and familiar technology, warrants ease of operation and availability of trained personnel.

 

Your case, would further warrant the study as suggested by Art. Typically I would go for 4x400 MMSCFD which warrants margin in case of increase in sales gas volume by the upstream companies. Furthermore, design optimization can be made in this case through common utilities.

 

Please go through your own research and let me/us know of what you have come across. Surely would want to hear you comments in this project because this one seems to be once in a lifetime project development opportunity.